Industrias Peñoles, S.A.B. de C.V.

Thanks, operator, and thanks everyone for joining us today. With me this morning are Bryan Sheffield, our Chief Executive Officer; Matt Gallagher, our Chief Operating Officer; and Ryan Dalton, our Chief Financial Officer.

During our prepared remarks, we’ll be referencing the industry presentation we posted to our website. So I encourage you to download the presentation if you haven’t already.

You can find it on our IR page under Events and Presentations. During this call, we’ll be making forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws.

There are many factors that could cause actual results to differ materially from our expectations, including those we described in our news release and SEC filings. We may also make reference to non-GAAP measures.

So please see the reconciliations in our earnings release. First in our agenda this morning, Bryan will comment on our progress and plans, next Matt will discuss our operating performance last quarter, Ryan will then walk through our financial results and guidance for 2015 and after that we’ll be happy to take your questions.

With that, I’ll turn the call over to Bryan.

Thanks, Brad, and good morning everyone. As I said in our press release, the fourth quarter was a strong finish to a banner year for Parsley Energy.

We became a public company in May through the second largest E&P IPO of all time. We completed our first horizontal well early last year and we’ve now completed more than 25 horizontal wells with basin-leading IP rates.

And as we’ve transition from a vertical drilling company to a horizontal drilling company, we’ve grown net production 184% versus 2013 averaging 14.2 MBoe per day in 2014. More than 9% of the production growth came through the drill bit.

As you can see on slide four, over the course of the year, we added mainly to our premier asset base in the heart of the Midland Basin. Based on the six rig run rate and using conservative 870 foot between well spacing, or 6 wells/zone/section, we now have eight to nine years of horizontal drilling inventory in the Wolfcamp A and B formations alone.

And we’re confident [indiscernible] of strong results across the entire location count. So down-spacing is a lower priority for us at this point.

We are optimistic about the down spacing opportunity which would add even more years on Wolfcamp A, B inventory. Recently we bolted-on around 8,500 net acres, primarily in Northwest Reagan County, in what we consider the core of the core of the Midland Basin.

This is a gem of an asset that increases the average lateral length of our inventory and further fills in what is shaping up to be a prolific drilling corridor for Parsley, ranging from South Central Midland County down to South East Reagan County. Reserves increased dramatically in 2014, with proved reserves up 66% year over year to 91 million Boe.

Proved developed reserves increased 126% to 46 million Boe. Total reserves increased 36 million Boe, replacing 694% of production volumes and close to 70% of the total reserve growth is organic.

Turning to Q4 in particular, production increased 19% from Q3 to 18.2 MBoe per day. The chart on slide five shows that oil volumes growth was particularly strong, up 31% quarter-over-quarter.

Wells acquired from Cimarex accounted for a portion of this, where organic oil growth was very strong at 20%. Unit cost trends were encouraging in Q4, with LOE per BOE down 13% and G&A per BOE down 8% sequentially.

Our Wolfcamp B wells continued to shine, with our two most recent wells establishing company records for scaled IP rates. These wells drilled in Upton County generated peak 30-day IP rate of 240 Boe per day per 1,000-foot.

Slide six outlines our 2015 capital program. In Q4 we demonstrated our willingness and ability to quickly shift course in response to changing conditions.

We have planned to exit the year with 6 horizontal rigs and 4 vertical rigs and we quickly cut back 5 horizontal rigs and 1 vertical rig. Consistent with this slowdown, development spending was 20% lower in Q4 than in Q3.

Despite lower CapEx, we delivered 12% organic production growth in the quarter. Periods of lower commodity prices highlight differences in asset quality.

We are fortunate, given our already low and improving cost structure along with prolific IP rates, to be able to generate attractive returns at commodity prices substantially below where they are today. So as we went through the budgeting process, the fundamental guideline on drilling activity relates to the balance sheet, not returns, which are and have been more than sufficient to support additional drilling.

Following our recent equity offering, our balance sheet is quite strong with net debt to last 12 month EBITDA below 2 times. We’ve chosen the way our activity towards the back half of the year in anticipation of decline in service costs and perhaps, higher commodity prices as well.

In effect, we’re prioritizing returns over near-term growth. At the same time, we will be prepared to accelerate the peer-leading growth profile when we see commodity prices stabilize and appropriate service cost concessions, which are well underway.

And with a relatively low base decline rates and strong IP rates from new horizontal wells, we’re still projecting 30% year-over-year production growth this year, despite cutting CapEx in half versus 2014. So we’re looking at a very efficient capital program.

Matt and Ryan will give more details on our operations and outlook, but I want to emphasize that we’ve delivered on what we promised at our IPO last spring, we built a first-class asset base from which we’re driving value in an efficient and disciplined manner. With that, I’ll turn it over Matt.

Thanks, Bryan. It was an exciting quarter on the operational front as we continue to produce robust Wolfcamp B wells, saw encouraging results from recently acquired wells and took preliminary steps on our delineation program.

Turning to slide seven, we continue to build an enviable track record of highly productive horizontal wells. As the chart indicates, our Wolfcamp wells are meaningfully exceeding our 690 MBoe public data type curve, which we updated in November.

Through six months, our actual results are outperforming our type curve by approximately 65%. This chart includes every one of the Wolfcamp A and B wells we put on production so far.

We’ve drilled and completed four Wolfcamp B wells since our last results update, all in our core acreage area and their average 30-day IP rate came in at a pace sitting 216 Boe per day per 100 stimulated feet, pushing our average for all Wolfcamp wells completed in the quarter to date north of 200 Boe per day per 1000 stimulated feet. Our actual results today represented by the grey line, which generated approximately 40% rate of return at current strip pricing and D&C cost.

Even at the current strip, our Wolfcamp wells are on track to pay out in an average of just two years. On the cost front, we are seeing a truly cooperative and interactive approach from our vendor network.

Across the drilling and completion spectrum, we have roughly 10% reductions in hand from Q4 pricing levels. In particular, we’re off roughly 25% on our frac unit costs alone.

Many have matched the 20% reduction request, but we do need another leg down from here. We’re modeling in additional 10% reduction in place for the second half of the year, which we feel is easily achievable considering we will have turned through Q4 tangible inventories and incremental rigs will be spot pricing.

The map on slide eight shows our completed horizontal wells by bench to date. As you can see, throughout 2014 we’ve methodically drilled the Wolfcamp B all the way across the map from the north-west to the south-east.

And the Wolfcamp B is proving prolific across our horizontal focus area. It’s important to understand that not all Wolfcamp B is created equal.

Slide nine shows that as you get closer to the basin deep, in Central Midland, Upton and Martin counties the target has additional institute pressure and is much thicker as compared to areas climbing towards the platform to the west. This combination of thickness and pressure is why our Wolfcamp B wells are showing basin-leading productivity and also potential for additional flow units or horizontal target zones with Wolfcamp B and A in our areas.

The Wolfcamp complex continues to thicken as we go to the south-east into our horizontal focus area throughout the Reagan County, but we do get shallower in those areas which makes drilling less expensive. For other zones, deeper than the Wolfcamp B this principle holds true.

Deepest, thickest and higher pressured in the center of the basis. Meanwhile, the [indiscernible] consistent over a large area expansion throughout the basin and is proven by over 60 years of development in and around our acreage.

We are excited about industry horizontal results in Spraberry and believe that bodes well for our Spraberry locations, given the consistency of the Spraberry. Results from our first couple of Wolfcamp A wells have been strong and early results from our most recent Wolfcamp A well, which does not quite have 30 days of production history, is on track to be our best by far.

Again, these results are reflected in our actual Wolfcamp results to date on slide seven. The Wolfcamp A actually has more oil in place than the Wolfcamp B in some areas.

So the size is tremendous. We got right to work on a recently acquired Cimarex acreage.

We now have completed two Wolfcamp B wells that had already been drilled when we acquired the properties. As expected, the well results are looking good, averaging a stellar 161 Boe per day per 1000 stimulated feet.

The target zone was slightly different than our target zone when we drilled Wolfcamp B wells, so this has been a nice early test on how additional zones within our Wolfcamp B will perform. We recently completed our first horizontal Atoka and Cline wells, which are providing a lot important data.

The Cline well, located in the Reagan County in our tier 1 area, had a 30-day peak rate of 543 Boe per day, which is a strong result considering we were only able to plug and perforate 2,500 feet of the roughly 4,000 foot long interval. The Atoka well was a learning experience.

We ended up landing in a tertiary target after two sidetracks. Production to date has been weak, with a 24-hour IP of 310 Boe per day and a 30-day peak tracking between 100 and 200 Boe per day.

Conversely, we also recently completed a vertical Atoka Penn-only well a few miles away that is on track to be the most prolific of the more than 650 vertical wells we’ve drilled as a company. Slowing tubing pressures for this well are over 5,000 pound, with rates of 250 plus barrels of oil per day and 2.5 million cubic feet per day on a 12/64" choke which is about the diameter of a pencil.

So we continue to be enthusiastic about landing a horizontal well in the productive Atoka zone timed to our vertical wells. Slide 10 shows the split anticipated program in 2015, which demonstrates that we are pleased with the results from one side of our development area to the other.

Having said that, we are sticking with the most statistically proven bench to date for the vast majority of our work, the Wolfcamp B. We’ll have a handful of Wolfcamp A wells in a select few delineation wells throughout the year.

It’s worth noting that given our large scale historical programs, we have significant infrastructure in place. We operate roughly 100,000 barrels per day of water disposal capacity, 200,000 barrels per day of water sourcing capacity, and 6 million barrels of water storage capacity scattered among roughly 50 frac ponds Our third party pipeline to Colorado City is trenched and laid to our acreage and they are now installing the lease level gathering sites.

We believe this historical activity and our location within the basin allows for some of the highest concentration of investable dollars going towards Midland Basin core D&C activity. Turning to slide 11, I want to elaborate briefly on Bryan’s comments on reserve growth.

We voluntarily wrote-off 14 million barrels of oil equivalent of vertical PUDs and associated recompletions on the assumption that we would run no more than two vertical rigs over the next five years. Even with this reduction, we grew proved reserves to 66% year over year, consisting of 126% increase improved developed reserves and a 44% increase in PUDs.

We’ve only booked 41 horizontal PUDs to date, representing just 2% of our horizontal drilling location count. With more than 1800 horizontal locations in our drilling inventory and no assumed benefit from downsizing, we anticipate years of strong reserve growth.

Slide 12 supports our growing excitement about our Trees Ranch prospect in Southern Delaware. We completed our third vertical exploratory well during Q4 and have just started testing the deep PEM zones.

Production from our previously completed vertical wells remains roughly flat at healthy rates. Although we are putting the exploratory efforts [indiscernible] for the time being, we’re very encouraged by all the data that we’ve gathered so far and we’re excited that based on the offset well data that you can see on the map, it appears that the Wolfcamp play is heading right towards us.

Before turning it over, I want to say that I’m exceptionally proud of our team which has made a major leg up technically over the past 18 months as we’ve transitioned to a horizontal operator. And now, I’ll turn to Ryan to cover our financial results and outlook.

Thank you, Matt. In the fourth quarter, adjusted net income was $0.02 per diluted share and for the full year 2014, it was $0.39 per diluted share.

Adjusted EBITDA for Q4 2014 was $51.8 million and for full year 2014 it was $206.1 million. Slide 13 provides quarterly and annual operating metrics.

As Bryan stated, net production averaged 18.2 MBoe per day during Q4, up 19% over Q3, with growth dominated by oil volumes, which increased 31%. Notably, oil production represented 57% of total production in Q4, up from 52% in Q3.

Oil volumes, as a percent of total production, should hold steady over the next couple of quarters and then resume an upward trend as drilling activity picks up in the second half of the year. Commodity price realizations were down across the board again in Q4, with oil down 26%, gas down 12%, and NGLs down 31% before the impact of derivatives.

Unit cost trends were favorable in Q4, with all costs within or below our guided ranges. Lease operating expense per Boe decline 13% to $6.49, while general and administrative expenses per Boe declined 8% to $6.38.

Depreciation, depletion and amortization expense per Boe increased 45% to $20.92, driven by recent acquisitions. CapEx came in at $132 million in Q4, down 20% in Q3 as the effect of few vertical rigs outweighed the effect of adding horizontal rigs, albeit at a slower pace than originally anticipated.

Slide 14 shows our strong liquidity position. On February 6, we priced a private placement of common stock generating $231 million of gross proceeds.

The purpose of the offering was to repay our revolver draw related to our Q4 Reagan County acquisition and strengthen the balance sheet. Having not been public for a year and therefore not eligible for a shelf registration statement that would enable us to issue equity overnight, we opted to issue equity through a private placement.

We were very pleased with demand for this offering, which drove a significant upsize. We used proceeds from the offering to pay down $120 million balance on the revolver with the rest going to cash to fund our 2015 capital plans.

As a result, we now have a very strong balance sheet and liquidity profile. We have an undrawn credit facility of $562 million, down just slightly following the recent hedge roll downs which I will discuss in a moment.

Currently, we’ve limited the lenders aggregate commitment to $365 million. Based on that committed amount and with more than $150 million of cash at the end of Q4, pro forma for the equity offering, we have total liquidity in excess of $500 million.

With bank price index coming down in recent months, we could see a haircut in our borrowing base at the spring determination, but we expect that any reduction will be significantly mitigated by our strong reserve growth. At the time of the redetermination, we will likely increase the commitment level to the full amount of the borrowing base.

Over the last few months, we monetized a portion of our hedge position by rolling future positions to lower put spreads. Slide 15 provides a graphic of this hedge activity.

Net of the cost of entering new contracts with lower strike prices, we’ve converted unrealized gains into $63 million of cash. Approximately $46 million of this cash is in our 2014 yearend cash number with the rest of the activity having incurred n 2015.

Total barrels hedged are unchanged with most of estimated 2015 production hedge this year and more barrels hedged next year than this year. And we expect to use some of the proceeds from the roll downs to add to our 2017 hedge position.

Unlike swaps, the structure of our hedge position allows us to retain a great majority of the upside if oil prices were to rally. Turning to guidance, which you can see on slide 16, as we announced after our equity placement of a couple of weeks ago, we expect to spend between $225 million and $250 million on development activities this year.

Of that total budget, $195 million to $210 million is earmarked for drilling and completion costs, with the balance going towards infrastructure including facilities. We expect to complete 30 to 35 gross horizontal wells and 18 to 22 gross vertical wells this year, with average working interest around 90% for both horizontal and vertical drilling.

Horizontal drilling and completion activity should run in parallel, but we only intend to drill about half as many vertical wells as we complete in 2015. While we will be completing some vertical wells in the first quarter that we drilled in the fourth quarter, vertical activity will be limited this year to wells required to hold leases.

So our lone vertical rig will only operate as necessary over the course of the year. With cash on the balance sheet and expected cash flow, we shouldn’t need to draw on our revolver to fund our 2015 drilling plan.

We expect unit cost to hold near current levels after study declines over the course of 2014 with both LOE and G&A per Boe between $6 and $7 and production and ad valorem taxes should be between 6% and 7% of revenue. I’d like to emphasize the shape of our capital spending.

We expect to operate three horizontal rigs on average in 2015, but activity will be weighted toward the second half of the year with two horizontal rigs running on average in the first half and 4 in the second half. We expect to generate 30% year over year production growth in 2015, even with CapEx down 50% versus 2014.

Of course, if we reverse the pattern of activity year over year production growth will be higher. But again, with currently depressed commodity prices and service cost coming down, we think it makes sense to slow down quickly and pick back up in a few months.

To wrap up, with a strong financial profile and a first class acreage position, we look forward to building on our successful first years of public company. With that, operator, we’d like to take questions.

Just a quick question on the select delineation wells that you scheduled for 2015, can you walk through what those are and your objectives for that program?

We are going to have – there’s not a whole lot on the books, but we’ll have another Atoka well and then we’ll have couple of Cline wells in the mix as well.

And you talked about the trajectory of your capital spending throughout the year, so I guess, how should we expect your cash flow outspend to look throughout the year as well, given your hedge position?

On CapEx, definitely you’re going to see a dip in Q2 as we put rigs, stack rigs for a while, with CapEx building towards Q3 and Q4. On the hedge monetization, we’ve since performed similar trades that we started in Q4 across all of 2015.

And so I think cash outspend should follow the CapEx.

And just one last one, if I could, I just wanted to get your thoughts on where your current differentials are on the oil side relative to WTI and if you have any expectations for full year 2015 that you can share with us for modeling purposes?

To clarify, our oil realizations, we do have a reduction for transportation and gathering that some of our peers were able to split out. And so when we model our oil realizations, we do take [indiscernible] which you can do what you want there, and then also add a couple of bucks for transportation.

Things are going to change when the pipeline comes online in late April. So I would say 50% or 60% off our production, and all that you guys know what deal we cut with the end user.

Across the inventory, all the zones went up a good bit, expect for the lower Spraberry which stayed the same, is that because the acres that you all did pick up you don’t think it’s prospective or you just don’t have enough data yet at this point?

No, that’s just a matter of the ownership we picked up there in the quarter where we got the Cimarex and the Anadarko packages, those were mainly Wolfcamp rights and deeper.

Below Apache units and primary units.

On the Southern Delaware, obviously, you’re highlight the results continue to come your way, I know there is no plans at the moment, but what would you need to see to have you all decide to try your first horizontal?

I think as we get into the back half of the year and if things are stabilizing, we see the cost reductions in place, that’s one of the first places we’d like to get back to testing a horizontal well over there.

So being mindful that you guys encountered some weather in January but at the same time once everything was back online, I think you mentioned in the early part of February you guys were doing about 20,000 barrels a day equivalent or so. In conjunction with you guys deferring completions to the back half of the year, should we think about high watermark or low watermark rather if production being in the second quarter or was the effect of that weather in January enough to make the first quarter kind of low watermark of production this year?

When you look at the shape of our CapEx spend this year only averaging two horizontal rigs in the first half, that’s really going to roll through to low watermark in the third quarter-ish and then you exit with modest growth year over year on Q4 to Q4.

Given that you guys have consolidated quite a bit of acreage over the last few years and even with this most recent acquisition in Reagan County, how are you guys seeing the M&A landscape right now, are you seeing pretty attractive pricing on leases, are you seeing availability of things out there, how can you characterize that?

I think about a month ago the spread was pretty wide and I’m seeing that tighten a bit. It’s pretty interesting, you’re seeing tier 1 versus core, the prices are starting to come in, there is a few land guys with deals out there, I think they’re still seeing a high number and slowly it’s pretty interesting to put the assets and closing in overtime through negotiations, but these aren’t small little items that will stand up 420s and 640 tracks.

There are a couple of larger deals out there, but I believe those guys out there still have high numbers in their head.

I wanted to ask about these two good Wolfcamp, two best ones, Atkins and Ratliff, I wondered if you could share your thoughts on to what you attribute that – those really great IPs, how much of that is due to where it is situated in the basin or because of the rock towards the deeper part of the basin there and how much of it may be attributed to the design of the well, whether it’s you landed or the design completion?

We were on a program pressing forward, very well at a time, on our compression technique, these were our latest wells completed that did have idealized design on pounds of sand per foot and footage per stage. So we got to our goal there with the commodity pullback we’re not going to continue to press that right now, we’re sticking with that current design as frac cost come in and so we’re not going to continue to push the envelope there, but we did see the positive results on the completion side.

And also it is in the heart of the core and anticipated good results there through the offset results as well.

So if I understand you Matt, it was a high dollar completion that might not be at the margin make sense with the current service costs and commodity price environment, but we can maybe see a return to that in the back half of 2015 or 2016 as prices shift?

I think we continue with that completion technique, we’re just happy with where it’s at currently and we’re not going to make additional stage compression for instance which is the largest driver of additional cost, cost per stage. So we’ll continue right now.

So that’s the new normal?

Yes.

And then if I could ask a bit on your Atoka well, the one you had to sidetrack twice, I can gather from your plans, you’re going to drill another one, or you have plans for one 2015, but I wondered if you could talk a bit about what you saw, what happened, but really with an eye to what if anything you learned that either would encourage you about Atoka as a horizontal target or discourage you, presumably you’re not discouraged if you have another one plan, but wondered if you could just talk about what you saw and what happened and would you learn?

Good question. In fact we are very encouraged with the Atoka program, was an operational hiccup on the drilling site there, but when you have just a few miles away and in the same time period we just completed it at the end of the fourth quarter as massive Atoka PEM only well, 5000 pounds of flowing tubing pressure has been pegged there at 5,100 pounds for over a month now, we’re abating this thing open, it’s on a 12/64 choke today, which I mentioned was stiffening to the size if you look down the barrel of your pencil, that’s a lot of fluid moving through a small area.

So these are the things that are really getting us excited about the Atoka prospects and just need to take what we learn from the first well which we have identified the improvements we need to make and apply it to our next well in the program.

I’m not looking at a full comparable set of data for me, but that 5100 pounds of flowing pressure, that’s remarkable, is that significantly higher than what you guys have seen in other Atoka wells and is it – if that’s just a few miles away, was that one of the – did you encounter higher pressure than anticipated, is that one of the issues?

We did encounter pressure issues during the drilling of this well when we do – we know we’re going in to higher pressure regime. But having said that, this particular well that I just mentioned is our highest pressured well, but we generally see 3000 pounds plus in the early days of these wells.

We have five or six wells that are tracking over a million barrels on a vertical basis and those are the ones in the 3000 pound early flow regime. So this recent well is very encouraging and we are still excited about the program as a whole.

Matt, I appreciate the pencil analogy there for the choke sizes for a finance guy that brought the life actually, so thanks. As it pertains to the outperformance of these wells, it’s pretty drastic in terms of how far and even the 830 type curve that you got in your slide deck here, just curious at the end of the day what you think you guys could sell out at and what you’re going to need, how much history, or what you’re going to need to see to be more confident maybe putting out a much higher number?

Our first horizontal well, we only have 12 months of data, so it’s difficult, I started the company with 5000 well production data logs and so that’s what I’m kind of geared towards, but it’s hard to increase the curves dramatically until I see a lot of results. So I need to see more wells past 12 months, I think we’re right around 30, right, of Wolfcamp B.

If we can see about 10 to 15 with 12 months of production, I could see just working on that curve. Matt, do you want to comment on that?

No, I think that’s right. As the double digit well count marches forward, kind of slide 7 there, into months 10 or 11 would be more comfortable updating that and all the data today it is very encouraging as we are displaying here.

And on the M&A front, just curious when the last deal was struck, is that before oil really kind of took your nose down and really I guess what I’m trying to get to is as you go forward, Bryan, are you comfortable paying a similar type number on a per acre basis that you did with this last acquisition?

We got the same question when we did our pipe deal with investors and yes, we did sign an LOI before the OPEC meeting and I think we signed – I decided to sign the PSA after the OPEC meeting which meant we closed in December. I do feel like, you can ask me the question would you do the same deal today and I will look at the environment, yes [indiscernible] but I do believe that this is a great price compared to the price that we’re trading at today.

So I think maybe this is the average price right now and I do believe prices will go up from the 15,000 to 16,000 range once costs come down.

Just real quick Bryan on the recent acreage acquisition, most of that acreage is held by production, is that right?

Yes, 73% of it is HBP.

Okay. So you don’t have to put a rig on it right away in terms of worrying about lease expirations?

Majority of it – the rest of it with the leases, Anadarko signed a five-year term assignment to us because the rest of it there’s no minerals and so they signed a five-year term with us.

Matt, my first question looking at your early stage production relative to your pipe curve, just one observation is you’re significantly outperforming in perhaps some of the early months and it comes a little bit closer towards the type curve overtime, could you just comment on that early stage performance and it comes down a little bit overtime, is that just low, a fewer number well, it’s in the back end of that data set?

Yeah, the back end of the data set is just impacted by some obsolete gas compression that we had out there through the first wave getting these wells online, with a previously used vendor and a older vintage compressor. So we’ve made a switch on that side and the peaks of those troughs are indicative of how the well is going to perform.

And as we get the newer vintage wells online with our newer set up, that’s a higher run time in those cases. So that’s all that’s going on in the tail end on those one to two wells.

Matt, second question, one of your peers up north has shifted almost exclusively or will shift to kind of a Wolfcamp B heavily focused development program in a period of lower commodity prices, how do you compare in contrast your thoughts on some of your early Wolfcamp A results versus the B?

A is encouraging, still highly economic and on the call we mentioned how we had our most recent A well is the strongest to date, it’s essentially tracking our B performance, but again – we don’t quite have 30 days on it, so we’re encouraged about what we see, but definitely in these times volatility and the commodity pricing, we just want to pull back to our statistical data here and hit the known quantity, but we’re marching forward on the A development and it looks good as well.

One operational question, you mentioned targeting a different or an additional zone within the Wolfcamp B in Reagan County, can you talk about that in little bit more detail on what that could imply to your development spacing pattern?

I think slide 9 is a good slide to reference and those wells in particular are on the eastern edge of our core if you’re looking at the bottom picture there and you can see that the B continues to thicken as you go to the south-east. And there are multiple targets within that, we’ve been honing in on one particular marker where we land most of our zones, our wells, but we’ve had identified some other ones and that’s where these particular wells were landed within a couple of hundred feet.

So it does show a new productivity profile on a new landing zone. And as we march, we’re not counting to an inventory right now, but it’s a good early indicator and then late 2015 into 2016, we will need to proceed with dual-stack testing within the same zone to see what kind of impact that’s going to have for inventory in our company going forward.

This is just a good data point to have in our back pocket.

And I guess just one more longer term question, just back on the cash flow outspend, you all do have quite a bit liquidity today and get pretty high returns even in this environment, so I guess my question is if we sort of stay in a depressed commodity price environment for more descended period of time, do you all have any goals with respect to getting to cash flow neutrality?

Michael, I don’t think that’s a high priority right now, it’s really about protecting the balance sheet, protecting leverage. Our current plan allows for prices to retreat even more and we still didn’t even need to touch the revolver this year, which was an important goal coming out of our pipe couple of weeks ago.

I’ll make a comment on that, we’re trying to aim here and we’re waiting for cost to come down, we don’t need oil prices to come back, but we want to return to a higher growth company. And so we’re just in a patient mode over the next few months and that’s why we designed our CapEx program more in the back half of the year.

We appreciate everyone, we’re going to be on a couple of conferences next week. We’ll look forward to seeing all you guys there.